Methodologies and apparatus for the recognition of production tests stability

ABSTRACT

A method for analyzing flow of a fluid through a flowmeter is provided. In an embodiment, the method includes receiving multiphase flowmeter data representative of a characteristic of a multiphase fluid flowing through a multiphase flowmeter and segmenting the multiphase flowmeter data into time blocks. The data in the time blocks can be analyzed using time-domain analysis or frequency-domain analysis to determine flow stability. The time-domain analysis can include analyzing time blocks in a time domain to determine whether measurement distribution in the multiphase flowmeter data of the analyzed time blocks represents stable flow of the multiphase fluid. The frequency-domain analysis can include converting the multiphase flowmeter data of the time blocks from a time domain to a frequency domain and identifying time blocks in which contribution of low-frequency components in the frequency domain is below a contribution threshold. Additional systems, devices, and methods are also disclosed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of co-pending U.S. patent applicationSer. No. 14/830,694 filed Aug. 19, 2015, now U.S. Pat. No. 10,309,816,which application claims priority to U.S. Provisional Patent ApplicationNo. 62/040,584 filed Aug. 22, 2014, each of which is herein incorporatedby reference.

BACKGROUND Field

This disclosure relates to well testing and more particularly to methodsand apparatuses for performing and interpreting production testmeasurements.

Description of the Related Art

Hydrocarbon fluids such as oil and natural gas are obtained from asubterranean geologic formation, referred to as a reservoir, by drillinga well that penetrates the hydrocarbon-bearing formation. Once awellbore is drilled, the well may be tested for purposes of determiningthe reservoir productivity and other properties of the subterraneanformation to assist in decision making for field development. Variouscomponents and equipment may be installed in order to monitor andconduct flow tests while producing the various fluids from thereservoir.

Well testing is done to provide reservoir characterization, estimationof well deliverability, evaluation of well completion and perforationstrategy, and assess efficiency of performed operations on a well, suchas drilling, completion, perforation, stimulation, etc. During a welltest, one parameter obtained is the flow rate measured at the surface.Various types of analysis may be performed on the results of the flowtests to determine formation, fluid, and flow characteristics, such ason the data measured using flowmeters. Wells often produce a combinationof water, oil and gas, making flow rate measurements rather complex.

One conventional way of measuring the flow rate is by separating fluidphases in a multiphase flow and then measuring the individual phaseswith single phase flowmeters. Separation into and measuring of singlephase flows are generally considered very accurate. Although singlephase flow measurements are generally trustworthy, a difficulty ariseswhen separation of the fluids is incomplete, thus providing a mixture offluid phases (e.g., gas bubbles in oil) to be measured by a single phaseflowmeter and inaccurate results. Another potential drawback is that alot of information about the behavior of the fluid flow in theproduction well may be missed, as fluid flow rate is measured afterseparation. Consequently, the desire arose to measure the multiphaseflow rate before separation using a multiphase flowmeter. However,multiphase flow measurement is very complex and its development forindustrial use has been relatively recent.

SUMMARY

Certain aspects of some embodiments disclosed herein are set forthbelow. It should be understood that these aspects are presented merelyto provide the reader with a brief summary of certain forms theinvention might take and that these aspects are not intended to limitthe scope of the invention. Indeed, the invention may encompass avariety of aspects that may not be set forth below.

In an embodiment of the present disclosure, a method includes receivingmultiphase flowmeter data that represents a characteristic of amultiphase fluid flowing through a multiphase flowmeter and segmentingthe data into time blocks. The method also includes analyzing thesegmented multiphase flowmeter data in the time blocks using time-domainanalysis or frequency-domain analysis to determine stability of the flowof the multiphase fluid through the multiphase flowmeter. Thetime-domain analysis, if used, includes analyzing at least some of thetime blocks in a time domain to determine whether measurementdistribution in the multiphase flowmeter data of the analyzed timeblocks represents stable flow of the multiphase fluid through themultiphase flowmeter. The frequency-domain analysis, if used, includesconverting the data in at least some of the time blocks from the timedomain to a frequency domain. The data in the frequency domain caninclude low-frequency components below a frequency threshold andhigh-frequency components above the frequency threshold. Thefrequency-domain analysis also includes identifying time blocks in whichcontribution of the low-frequency components in the frequency domain isbelow a contribution threshold.

In another embodiment of the present disclosure, an apparatus includes afluid conduit and a sensor coupled to the fluid conduit for measuring acharacteristic of a multiphase fluid produced from a well and routedthrough the fluid conduit during a well production test. Further, theapparatus includes a computer for analyzing the multiphase fluidcharacteristic measured by the sensor to determine a flow rate of themultiphase fluid through the fluid conduit, and also for determiningflow stability of the well production test through analysis of themeasured characteristic in both time and frequency domains.

In an additional embodiment, a method includes analyzing measurementsacquired with a multiphase flowmeter, the measurements indicative of aflow characteristic of a fluid routed through the multiphase flowmeterduring a well production test. Analyzing the measurements includessegmenting the measurements and analyzing the segmented measurements inboth time and frequency domains. The method also includes determining,without analyst intervention, whether the well production test can beconsidered stable based on the analysis of the segmented measurements inboth the time and frequency domains.

Various refinements of the features noted above may exist in relation tovarious aspects of the present embodiments. Further features may also beincorporated in these various aspects as well. These refinements andadditional features may exist individually or in any combination. Forinstance, various features discussed below in relation to theillustrated embodiments may be incorporated into any of theabove-described aspects of the present disclosure alone or in anycombination. Again, the brief summary presented above is intended justto familiarize the reader with certain aspects and contexts of someembodiments without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described withreference to the drawings, wherein like reference numerals denote likeelements. It should be understood, however, that the accompanyingdrawings illustrate just the various implementations described hereinand are not meant to limit the scope of various technologies describedherein. The drawings show and describe various embodiments of thecurrent disclosure. More specifically:

FIG. 1 generally depicts a flowmeter for analyzing a fluid in accordancewith an embodiment of the present disclosure;

FIG. 2 is a block diagram of components of a computer of the flowmeterof FIG. 1 in accordance with an embodiment;

FIG. 3 is a flowchart for analyzing flowmeter data to identify stableflow through a flowmeter in accordance with an embodiment;

FIG. 4 is a graph of a liquid fraction of a multiphase fluid flowingthrough a flowmeter during a first production test in accordance with anembodiment;

FIGS. 5 and 6 are graphs of multiphase flowmeter data of the firstproduction test segmented into time blocks and converted into afrequency domain in accordance with an embodiment;

FIGS. 7 and 8 depict global and local maxima of kernel density estimatefunctions for the time blocks and generally show variation in thesemaxima between analyzed time blocks of the first production test inaccordance with an embodiment;

FIG. 9 is a graph of a liquid fraction of a multiphase fluid flowingthrough a flowmeter during a second production test, which exhibits astrong oscillating behavior, in accordance with an embodiment;

FIGS. 10 and 11 are graphs of multiphase flowmeter data of the secondproduction test segmented into time blocks and converted into afrequency domain in accordance with an embodiment;

FIGS. 12 and 13 depict a photon data signal and a differential-pressuredata signal of a multiphase flowmeter during the second production testin accordance with an embodiment;

FIGS. 14 and 15 depict global and local maxima of kernel densityestimate functions for the time blocks based on the photon signal andthe differential-pressure data signal of FIGS. 12 and 13, and generallyshow variation in these maxima between analyzed time blocks inaccordance with an embodiment; and

FIGS. 16 and 17 depict measured deviation of the global maxima of FIGS.14 and 15 over time in accordance with an embodiment.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of the present disclosure. It will be understood bythose skilled in the art, however, that the embodiments of the presentdisclosure may be practiced without these details and that numerousvariations or modifications from the described embodiments may bepossible.

In the specification and appended claims: the terms “connect,”“connection,” “connected,” “in connection with,” and “connecting” areused to mean “in direct connection with” or “in connection with via oneor more elements,” and the term “set” is used to mean “one element” or“more than one element.” Further, the terms “couple,” “coupling,”“coupled,” “coupled together,” and “coupled with” are used to mean“directly coupled together” or “coupled together via one or moreelements.” As used herein, the terms “up” and “down”; “upper” and“lower”; “upwardly” and downwardly”; “upstream” and “downstream”;“above” and “below”; and other like terms indicating relative positionsabove or below a given point or element are used in this description tomore clearly describe some embodiments of the disclosure. Whenintroducing elements of various embodiments, the articles “a,” “an,”“the,” and “said” are intended to mean that there are one or more of theelements. The terms “comprising,” “including,” and “having” are intendedto be inclusive and mean that there may be additional elements otherthan the listed elements.

Embodiments of the present disclosure generally relate to fluidanalysis, such as fluid analysis of produced fluids during wellproduction tests. More particularly, some embodiments include performingspecific analysis of raw measurements acquired by multiphase metersrelated to the total flow occurring through the meter to determinewhether a production test can be considered as stable (or not) withoutanalyst intervention, but processed data (e.g., flow rates, fractions,or ratios) could also or instead be analyzed to determine productiontest stability without analyst intervention. In an embodiment, a methodincludes analyzing blocks of data using several mathematical methodsbased on probability distribution functions as well as frequency-domainconversion of time series to assess whether flows that are potentiallyunstable over short periods of time (i.e., showing significantvariations in responses between successive time steps) are in factshowing a pseudo steady-state behavior that is characteristic ofdeveloped flows with a repeating behavior over the long term and trulyrepresentative of a well or pipeline performance.

Turning now to the drawings, an apparatus 10 for analyzing fluid isgenerally depicted in FIG. 1 in accordance with an embodiment. Whilecertain elements of the apparatus 10 are depicted in this figure andgenerally discussed below, it will be appreciated that the apparatus 10may include other components in addition to, or in place of, thosepresently illustrated and discussed. Moreover, while the apparatus 10may be provided in the form of a flowmeter (e.g., a multiphaseflowmeter) as shown here and described below in connection with certainembodiments, the apparatus 10 could be provided in other forms as well.Further, in at least some instances the apparatus 10 is used to analyzefluids drawn from subterranean formations. Such analysis could beperformed on fluids by the apparatus 10 downhole within a well or at thesurface.

As depicted, the apparatus includes a fluid conduit 12 for receiving afluid to be analyzed and various sensors coupled to the fluid conduit 12for measuring a characteristic of the fluid in the conduit 12. In thepresently depicted embodiment, the sensors include a radiation detector16 (which receives radiation from an emitter 14), a pressure transmitter18, and a differential-pressure transmitter 20. The emitter 14 can emitelectromagnetic radiation into the fluid, at least some of which isreceived by the radiation detector 16. In at least an embodiment, theemitter 14 includes a nuclear source (e.g., Barium-133) that emitsnuclear radiation through the fluid to the radiation detector 16.

To facilitate certain measurements, such as flow rate, the fluid conduit12 may be provided as a Venturi section having a tapered bore (e.g., aVenturi throat) to constrict fluid flow, as shown in FIG. 1. Thisconstriction creates a small pressure drop, which is measured with thedifferential-pressure transmitter 20. Further, in at least an embodimentthe emitter 14 and detector 16 are positioned about a Venturi throat inthe fluid conduit 12 such that the detector 16 receives radiation thathas been transmitted through fluid within the Venturi throat.

In some embodiments, the apparatus 10 is a multiphase flowmeter thatuses radiation at two or more different energy levels or wavelengths. Asone example, the apparatus 10 may use gamma radiation (e.g., emittedacross the Venturi throat) at two different energy levels. Theattenuation of the radiation may be measured and used to determineindividual phase fractions of oil, gas, and water in a multiphase fluidrouted through the flowmeter. The individual phase fractions and thedifferential pressure can be used to determine other fluidcharacteristics, such as mixture density, water-liquid ratio, and massflow rate.

The apparatus 10 also includes a computer 22 (which may also be referredto as a controller or a control unit) for determining characteristics offluid within the fluid conduit 12. In at least some embodiments, thecomputer 22 is provided in the form of a flow computer coupled with theother depicted components in a single unit to facilitate installation ofa flowmeter in a larger system (e.g., an oilfield apparatus). Morespecifically, the computer 22 is operable to determine characteristicsof fluids within the fluid conduit 12 from measurements collected by theother components. For example, the computer 22 can determine pressureand flow rate of the fluid. Further, a computer 22 of a multiphaseflowmeter can determine attenuation by the fluid of various levels ofradiation by comparing the amount of radiation emitted from the emitter14 to the portion of such radiation actually received by the detector16. The computer 22 can also use this information to calculate phasefractions (e.g., proportions of oil, gas, and water) for a multiphasefluid within the fluid conduit 12. Single-phase flow rates can beachieved by combining the phase fraction measurements together with thetotal flow rate measurement. And as described below, in at least someembodiments the computer 22 analyzes flow data in both time andfrequency domains to ascertain stability of fluid flow through theapparatus 10 (e.g., flow of a multiphase fluid produced from a wellduring a production test).

The computer 22 can be a processor-based system, an example of which isprovided in FIG. 2. In this depicted embodiment, the computer 22includes at least one processor 30 connected by a bus 32 to volatilememory 34 (e.g., random-access memory) and non-volatile memory 36 (e.g.,flash memory and a read-only memory (ROM)). Coded applicationinstructions 38 and data 40 are stored in the non-volatile memory 34.For example, the application instructions 38 can be stored in a ROM andthe data 40 can be stored in a flash memory. The instructions 38 and thedata 40 may be also be loaded into the volatile memory 34 (or in a localmemory 42 of the processor) as desired, such as to reduce latency andincrease operating efficiency of the computer 22. The coded applicationinstructions 38 can be provided as software that may be executed by theprocessor 30 to enable various functionalities described herein.Non-limiting examples of these functionalities include determination ofincident photon count rates on a detector, calculation of attenuationrates and phase fractions for a fluid, determination of flow rate, andanalysis of flow stability through the flowmeter (e.g., during aproduction test). In at least some embodiments, the applicationinstructions 38 are encoded in a non-transitory computer readablestorage medium, such as the volatile memory 34, the non-volatile memory36, the local memory 42, or a portable storage device (e.g., a flashdrive or a compact disc).

An interface 44 of the computer 22 enables communication between theprocessor 30 and various input devices 46 and output devices 48. Theinterface 44 can include any suitable device that enables suchcommunication, such as a modem or a serial port. In some embodiments,the input devices 46 include one or more sensing components of theapparatus 10 (e.g., detector 16, pressure transmitter 18, anddifferential-pressure transmitter 20) and the output devices 48 includedisplays, printers, and storage devices that allow output of datareceived or generated by the computer 22. Input devices 46 and outputdevices 48 may be provided as part of the computer 22 or may beseparately provided.

Further, while the computer 22 could be located with the fluid conduit12 and sensing components of the apparatus 10 as a unitary system (e.g.,a flowmeter), the computer 22 could also be located remote from theother components. Further, the computer 22 could be provided as adistributed system with a portion of the computer 22 located with thesensing components at the fluid conduit 12 and the remaining portion ofthe computer 22 located remote from the fluid conduit 12.

Some embodiments of the present technique include mathematical analysisof multiphase flowmeter data to consider measurements linked to flowingfractions and flow velocity, indicative of the nature of a multiphaseflow through the meter. Indicators of flowing fractions vary dependingon the metering technology used and can, for instance, include gammadensitometry measurements or electromagnetic measurements. An indicatorof flow velocity used in some multiphase flowmeters is adifferential-pressure measurement, which may be taken across a flowrestriction or expansion (e.g., a Venturi tube). Computed flow ratescould also be used rather than raw measurements.

Turning now to FIG. 3, an example of a process for identifying stableflow through a flowmeter is generally represented by flowchart 60. Inthis embodiment, multiphase flowmeter data is received (block 62) andthen segmented into time blocks (block 64). The received flowmeter datacan include data representative of a characteristic of a fluid flowingthrough the flowmeter (e.g., apparatus 10) and collected by sensingcomponents of the flowmeter, such as photon count data or differentialpressure, over a period of time. In some instances, the period of timemay correspond to a well production test and the present technique maybe used to identify stable flow of the produced fluid during the wellproduction test. In a further example provided below, the data issegmented into time blocks that are two hours long, but the data couldbe segmented into time blocks of any desired length. The segmented timeblocks may also be overlapping (with portions of consecutive time blocksspanning the same elapsed time) or separate (with consecutive timeblocks having no overlap).

The multiphase flowmeter data in the time blocks are then converted fromthe time domain to the frequency domain (block 66). This conversion maybe performed in any suitable manner, such as with a Fast FourierTransform or another Fourier Transform. The converted data includeslow-frequency and high-frequency components that may be defined withrespect to a frequency threshold (i.e., with low-frequency componentsbelow the frequency threshold and high-frequency components above). Thefrequency threshold (like other thresholds described below, such ascontribution and variance thresholds) may be a pre-defined, arbitrarilyset threshold. The time blocks converted to the frequency domain can beanalyzed to determine the number of low-frequency components present.The presence of a large number of low-frequency components (e.g., aquantity above a contribution threshold) would indicate long-term trendsin the system and represent unstable flow. Accordingly, the processincludes identifying time blocks with contributions of low-frequencycomponents in the frequency domain below a contribution threshold (block68). The identified time blocks are also analyzed in the time domain todetermine whether measurement distribution in the multiphase flowmeterdata of the identified time blocks represents stable flow of themultiphase fluid through the multiphase flowmeter (block 70). In atleast some instances, the analysis of block 70 in the time domain of theidentified time blocks is performed after the identification of block 68in the frequency domain, although this order could be changed or theanalyses in the time and frequency domains could be performed inparallel. In still other embodiments, flow stability analysis could beperformed with just one of time domain analysis or frequency-domainanalysis, rather than both. For example, the conversion andidentification of blocks 66 and 68 could be omitted in an embodiment,while the time-domain analysis of block 70 could be omitted in another.Additionally, in the case of a production test and an identification ofstable flow, average production rates over a period of stable flow mayalso be determined (block 72).

In a more specific example of the process described above with respectto flowchart 60, and in accordance with an embodiment, a method foranalyzing data from a production test and identifying stable flow mayinclude segmenting the data to be analyzed in segments (i.e., timeblocks) of pre-defined duration, which could be selected based onspecific sub-sets of the test data. The segments can be separated (i.e.,non-overlapping), but considering overlapping blocks increases the timeresolution of the analysis. For instance, segments of two hours can bebuilt in fifteen minute intervals (from time 0:00 to 2:00, 0:15 to 2:15,0:30 to 2:30, and so forth). For each segment, the data may be convertedfrom the time domain to the frequency domain, for instance using a FastFourier Transform (FFT) to represent the same data in terms of a seriesof sinusoidal functions with various frequencies and amplitude. Themethod of an embodiment also includes checking for the presence of asignificant contribution of low-frequency terms indicative of long-termtrends in the system (non-developed flow) by comparing the amplitude ofthe Fourier transform below a given cut-off frequency to a pre-definedthreshold. If the logical check does return a positive response (i.e.,presence of significant low-frequency components in the signal), theflow can be considered as being in transient state and thus notstabilized.

Assuming that the production test has not been ruled out as unstablefrom the first check, a second analysis can be performed using the samelogic of data segmentation. This time, the analysis can be performedusing the time-domain subsets to analyze the stability of measurementsdistribution. In an embodiment, this includes using each subset ofpoints for at least some of the time blocks to build a probabilitydistribution function (PDF) by binning the multiphase flowmeter data ofthe blocks against ranges of values and matching the probability densityfunction for each block to a theoretical kernel density estimatefunction (KDE) extrapolating discrete, finite measurements to acontinuous function. Global and local peaks of the KDE may beidentified, and the corresponding value of those peaks between differentblocks may be tracked. The method may also include computing thevariations of those peak values between time steps, which may becompared to a pre-defined variance threshold to determine whether suchvariation is within a desired range (i.e., below the variancethreshold). If a pre-determined number of successive blocks show thatvariations remain with the desired limits for the various data typesconsidered (e.g., measurements linked to flowing fraction and flowvelocity) then the flow can be considered as fully developed andrepresentative of long-term stabilized production behavior. In otherinstances, probability-averaged values of the KDEs in intervals aroundthe peaks (e.g., five to ten percent on either side of the peak) can beconsidered, rather than single points. The method can also includedetermining average production rates over a period of stable flowidentified through the above analysis of the variations.

The presently disclosed techniques may be better understood withreference to FIGS. 4-8 corresponding to a first production test andFIGS. 9-17 corresponding to a second production test. With respect tothe first production test, FIG. 4 charts a measured liquid fraction of amultiphase fluid produced from a well and routed through the flowmeterover time. Data, such as photon counts or differential-pressuremeasurements, representative of a flow characteristic can be segmentedinto time blocks and converted from the time domain to the frequencydomain, as described above. FIGS. 5 and 6 depict segmented time blocks(referred to as records in these figures) of flowmeter data convertedinto the frequency domain. While the data of each segmented time block(or record) may be converted into the frequency domain, for the sake ofclarity FIGS. 5 and 6 depict just a representative sample of theconverted time blocks. The time blocks can also be analyzed in the timedomain to analyze flow stability, such as by analyzing peaks of kerneldensity estimate functions for the time blocks, which are generallydepicted in FIG. 7 (for a photon count data signal) and in FIG. 8 (for adifferential-pressure data signal).

As generally noted above, flows that appear to be unstable over shortperiods of time (i.e., showing large variations in responses betweensuccessive time steps) may in fact be showing a pseudo steady-statebehavior that is characteristic of developed flows, with a repeatingbehavior over the long term truly representative of a well or pipelineperformance. FIGS. 4-8 generally depict an example of a production testflow showing significant variations in the time domain (in FIG. 4), butthat is, in fact, just affected by high-frequency variations with nounderlying low-frequency trends (as represented in FIGS. 5 and 6) andshows stable (pseudo steady-state) responses over time (as representedin FIGS. 7 and 8).

With respect to the second production test example, FIG. 9 charts ameasured liquid fraction of a multiphase fluid produced from a well androuted through the flowmeter over time. Data representative of a flowcharacteristic, such as photon counts or differential-pressuremeasurements (which are depicted in FIGS. 12 and 13), can be segmentedinto time blocks and converted from the time domain to the frequencydomain, as described above. Like FIGS. 5 and 6 with respect to the firstproduction test example, FIGS. 10 and 11 depict segmented time blocks offlowmeter data of the second production test converted into thefrequency domain. Again, while the data of each segmented time block maybe converted into the frequency domain, for the sake of clarity FIGS. 10and 11 depict just a representative sample of the converted time blocks.The time blocks can also be analyzed in the time domain to analyze flowstability, such as by analyzing peaks of kernel density estimatefunctions for the time blocks, which are generally depicted in FIG. 14(for the photon count data signal of FIG. 12) and in FIG. 15 (for thedifferential-pressure data signal of FIG. 13). Additionally, FIGS. 16and 17 represent deviation of the peaks of FIGS. 14 and 15 over time.

In the second production test example corresponding to FIGS. 9-17, theflow behavior is characterized by a strong oscillating behavior of theflowing fractions, as generally represented by the oscillating liquidfraction signal depicted in FIG. 9. After performing the above-describedfrequency-domain analysis of segmented time blocks, however, it isapparent (see, e.g., FIGS. 10 and 11) that the data bears very littlelow-frequency content across the entire test duration and cannot beconsidered as transient. Furthermore, applying the secondary,time-domain analysis described above for photon counts indicative offlowing fractions (FIGS. 12, 14, and 16) and for differential pressureindicative of flow velocity (FIGS. 13, 15, and 17), it is apparent thatthroughout most of the test the nature of flow remains very stable, asshown by the stability of peak values (FIGS. 14 and 15) and the smalldeviations observed in the location of those peaks. As generally notedabove, deviation of the peak values may be compared to variancethresholds, such as two percent for the photon signal (as represented bythe horizontal, dashed line in FIG. 16) and five percent for thedifferential-pressure signal (as represented by the horizontal, dashedline in FIG. 17). This allows for an automatic definition of stableperiods, such as periods in which neither variance threshold is exceededor in which one or both variance thresholds are exceeded for a limitedperiod (e.g., for one or two records) before the deviations of the peakvalues fall back below the thresholds. In at least some embodiments, thedeviation data could be filtered or smoothed for analysis to reduceimpact of data spikes. For example, the deviation analysis could useaverages over several records or accumulations of deviations overseveral records (in which successive deviations of equal magnitude butin opposite directions would cancel one another). Variance is plotted inFIGS. 16 and 17 as an absolute value representing the magnitude (but notthe direction) of change, but it will be appreciated that the directionof change could also be considered.

The data acquisition system can be linked to a flow control system,making it possible to perform a sequence of tests without any humanintervention to determine whether a production test can be considered ascompleted or not, as well as minimize test time and ensure theproduction test is representative. The example above also shows asecondary application of frequency-domain analysis, which lies in thedetermination of the characteristic frequency or frequencies of areservoir-well-pipeline system that are of particular interest for flowassurance purposes.

In at least some embodiments, the frequency-domain analysis of segmentedtime blocks described above can also be used to identify a stabledeveloped slug flow during a production test. For example, thefrequencies in the two to ten cycle per hour range can be counted. Thepresence of many components (e.g., above a pre-defined threshold, like10,000 components) at a frequency within this range indicates slug-likebehavior of the flow. If the peaks of the frequency-domain data are alsoconstant over time, the flow can be defined as a stable developed slugflow. Further, the location of such peaks indicates the slug frequencyof the flow. By way of example, in FIG. 11 the presence of peaks atabout nine cycles per hour indicates a stable developed slug flow duringthe second production test, with a slug frequency of about nine cyclesper hour. Accordingly, the methods described above may also includeidentifying a stable developed slug flow during a production test.Further, the methods may include identifying a slug frequency of amultiphase fluid from multiphase flowmeter data in the frequency domain.

The foregoing outlines features of several embodiments so that thoseskilled in the art may better understand aspects of the presentdisclosure. Those skilled in the art should appreciate that they mayreadily use the present disclosure as a basis for designing or modifyingother processes and structures for carrying out the same purposes orachieving the same advantages of the embodiments introduced herein.Those skilled in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure, and that they may make various changes, substitutions andalterations herein without departing from the spirit and scope of thepresent disclosure.

1. An apparatus comprising: a fluid conduit; a sensor coupled to thefluid conduit for measuring a characteristic of a multiphase fluidproduced from a well and routed through the fluid conduit during a wellproduction test; and a computer operable to analyze the multiphase fluidcharacteristic measured by the sensor to determine a flow rate of themultiphase fluid through the fluid conduit, wherein the computer is alsooperable to determine flow stability of the well production test throughanalysis of the measured characteristic in both time and frequencydomains.
 2. The apparatus of claim 1, wherein the computer is operableto: segment sensor data representative of the characteristic into timeblocks, convert the time blocks from the time domain into the frequencydomain with a Fourier transform, and check for the presence of long-termtrends in the data by comparing an amplitude of the sensor data in thefrequency domain to a pre-defined threshold.
 3. The apparatus of claim1, wherein the sensor includes a differential pressure sensor formeasuring the characteristic of the multiphase fluid.
 4. The apparatusof claim 1, wherein the sensor includes a radiation detector formeasuring the characteristic of the multiphase fluid, the apparatusincludes a radiation source, and the radiation source and the radiationdetector are coupled to the fluid conduit such that the radiationdetector can receive radiation transmitted from the radiation sourceinto the fluid conduit.
 5. The apparatus of claim 4, wherein theradiation source and the radiation detector are coupled across a Venturithroat of the fluid conduit.